Water-sensitive smart coating for flow and corrosion tracking

ABSTRACT

A material composition may include one or more polymeric materials. The material composition may also include one or more inorganic particles comprising oxides, carbonates, sulfides, or any combination thereof. Further, the material composition may include one or more metal particles that produce a detectable change in an electrical property or an optical property based on a reaction with at least one of H2O, CO2, or H2S. The one or more inorganic particles and the one or more metal particles may be dispersed within the one or more polymeric materials.

BACKGROUND

The subject matter disclosed herein relates to systems and methods forassessing damage to a mechanical component due to corrosion, and to someextents also erosion and erosion-corrosion. More specifically, thesubject matter disclosed herein relates to techniques to create acorrosion detection coating, and assessing a likelihood and/or magnitudeof a corrosion damage to subsequently generate a component damage outputin a mineral and hydrocarbon extraction, fluid injection, includingcarbon dioxide or hydrogen underground sequestration.

Machine components may be used in various oil and gas operations, suchas midstream operations (e.g., processing, storing, and/or transportingof oil, natural gas, and natural gas liquids) and upstream operations(e.g., exploration, drilling, production, or extraction). During theoperation of mechanical components, the mechanical components aretypically subjected to a variety of wet environmental conditions thatcause corrosion, and in the presence of flow, also erosion anderosion-corrosion. Corrosion in most of its various forms wherein wateris present, sometimes essential, is the progressive loss or removal ofmaterials. Combating corrosion, including preventing it, are both majortechnical and economic challenges, particularly downhole infrastructuresof hydrocarbon production or fluid injection systems (e.g., ahydrocarbon production, water injection, gas sequestration systems).

BRIEF DESCRIPTION

Certain embodiments commensurate in scope with the originally filedclaims are summarized below. These embodiments are not intended to limitthe scope of the present technology, but rather these embodiments areintended only to provide a brief summary of possible forms of thetechnology. Indeed, the present system and method may encompass avariety of forms that may be similar to or different from theembodiments set forth below.

In certain embodiments, a material composition may include one or morepolymeric materials. The material composition may also include one ormore inorganic particles comprising oxides, carbonates, sulfides, or anycombination thereof. Further, the material composition may include oneor more metal particles that produce a detectable change in anelectrical property or an optical property based on a reaction with atleast one of water (H₂O), carbon dioxide (CO₂), or hydrogen sulfide(H₂S). The one or more inorganic particles and the one or more metalparticles may be dispersed within the one or more polymeric materials.

In certain embodiments, a method includes dispersing one or moreinorganic particles into one or more polymeric materials, wherein theone or more inorganic particles comprise oxides, carbonates, sulfides,or any combination thereof. The method also includes dispersing one ormore metal particles into the one or more polymeric materials, whereinthe one or more metal particles produce a detectable change in anelectrical property or an optical property based on a reaction with atleast one of H₂O, CO₂, or H₂S, and wherein a material compositioncomprises the one or more polymeric materials, the one or more inorganicparticles, and the one or more metal particles.

In certain embodiments, a system includes a surface monitoring systemthat measures data indicative of a change in surface characteristics ofa material composition along the surface. The material compositionincludes one or more polymeric materials, wherein the one or morepolymeric materials. The material composition also includes one or moreinorganic particles comprising oxides, carbonates, sulfides, or anycombination thereof. Further, the material composition includes one ormore metal particles that produce a detectable change in an electricalproperty or an optical property based on a reaction with at least one ofwater (H₂O), carbon dioxide (CO₂), or hydrogen sulfide (H₂S). The one ormore inorganic particles and the one or more metal particles may bedispersed within the one or more polymeric materials. The surfacemonitoring system also includes instructions stored on a non-transitorycomputer-readable medium and executable by a processor to identify thedetectable change in the electrical property or the optical property inresponse to the data and output an indication of the detectable change.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentdisclosure will become better understood when the following detaileddescription is read with reference to the accompanying drawings in whichlike characters represent like parts throughout the drawings, wherein:

FIG. 1 is a schematic diagram of a wellsite where a corrosion detectioncoating may be employed, in accordance with the present disclosure;

FIG. 2 is a schematic diagram of midstream operations where a corrosiondetection coating may be employed, in accordance with the presentdisclosure;

FIG. 3 is a flow diagram of an embodiment of a process for generating acorrosion detection coating, in accordance with the present disclosure;

FIG. 4 is a block diagram of an embodiment of a surface monitoringsystem, in accordance with the present disclosure;

FIGS. 5-8 are cross-sectional views of embodiments of a corrosiondetection coating on a machine component, in accordance with the presentdisclosure;

FIG. 9 is a schematic diagram of an embodiment of an electricalmonitoring system used with a corrosion detection coating, in accordancewith the present disclosure;

FIG. 10 is a schematic diagram of an embodiment of an optical monitoringsystem used with a corrosion detection coating, in accordance with thepresent disclosure; and

FIG. 11 is a flow diagram of a process for generating a machinecomponent damage output based on a change in electrical properties,optical properties, or both, of a corrosion detection coating, inaccordance with the present disclosure.

DETAILED DESCRIPTION

One or more specific embodiments of the present disclosure will bedescribed below. In an effort to provide a concise description of theseembodiments, all features of an actual implementation may not bedescribed in the specification. It should be appreciated that in thedevelopment of any such actual implementation, as in any engineering ordesign project, numerous implementation-specific decisions must be madeto achieve the developers' specific goals, such as compliance withsystem-related and business-related constraints, which may vary from oneimplementation to another. Moreover, it should be appreciated that sucha development effort might be complex and time consuming, but wouldnevertheless be a routine undertaking of design, fabrication, andmanufacture for those of ordinary skill having the benefit of thisdisclosure.

When introducing elements of various examples of the present disclosure,the articles “a,” “an,” “the,” and “said” are intended to mean thatthere are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements.Additionally, it should be understood that references to “one example”or “an example” of the present disclosure are not intended to beinterpreted as excluding the existence of additional examples that alsoincorporate the recited features.

In the present context, the term “about” or “approximately” is intendedto mean that the values indicated are not exact and that the actualvalue may vary from those indicated in a manner that does not materiallyalter the operation concerned. For example, the term “about” or“approximately” as used herein is intended to convey a suitable valuethat is within a particular tolerance (e.g., ±10%, ±5%, ±1%, ±0.5%), aswould be understood by one skilled in the art.

As generally discussed above, fluid handling components, such ashydrocarbon extraction components (e.g., machine components, storagetanks, or downhole components) used for oil and gas operations, mayincur damage due to flow or corrosion while in operation or beingstored. That is, certain downhole conditions may include the presence ofcorrosive fluids (e.g., water in combination with CO₂, H₂S, or both, anacid, or a base, or any combination thereof) and, at least in someinstances, relatively high temperatures (e.g., 25° C., 50° C., 100° C.,greater than 100° C.), and pressures that increase the likelihood ofcorrosion to the machine component. For example, such downholeconditions may occur during carbon sequestration applications, wherewell infrastructures may include injector and monitoring wells. Whensequestrating CO₂ (e.g., during carbon capture and sequestration (CCS))down a reservoir, pressures may be such that the CO₂ is compressed to bein a liquid or a supercritical state. The injected CO₂ is normally keptdry (e.g., having less than or equal to approximately 50 ppm, 100 ppm,200 ppm, 300 ppm, 400 ppm, 500 ppm, or 600 ppm of water). In general, alikelihood of corrosion increases as the concentration of waterincreases to relatively high ppm concentrations (e.g., greater than 700ppm, 800 ppm, 900 ppm, or 1000 ppm), where water can be trapped insupercritical CO₂ (e.g., Sc CO₂). Moreover, as the temperatureincreases, more water may be stored in Sc CO₂, that is indistinguishablefrom the supercritical CO₂. When water is in high concentrations,environmental conditions are created for corrosion to develop. Whenwater is also flown at high velocities, corrosion and potentiallyerosion start to take place, possibly leading to greater losses ofmaterials. In general, the corrosion may be difficult to detect due tothe mechanical component (e.g., a mechanical component of a hydrocarbonextraction system,) being disposed in a position that is difficult tomonitor, such as the mechanical component being disposed downhole orbeing transported on a vehicle.

Accordingly, the present disclosure is directed to techniques forimproving the detection of damage to mechanical components by combiningor dispersing tracers (e.g., metal particles and/or inorganic particles)into an engineering polymer to form a flow and/or corrosion detectioncoating (e.g., corrosion detection coating, flow detection coating, orboth) and applying the corrosion detection coating onto a surface of themechanical component. It is presently recognized that certain fluidsreleased downhole (e.g., CO₂ or H₂S), acids, and/or bases in combinationwith water may result in corrosion of materials, and as such, materialsreactive with at least water or the combination of water and otherfluids may be useful for monitoring potential corrosion to fluidhandling components, such as mineral extraction, hydrocarbon extraction,or sequestration mechanical components. The corrosion detection coatingfacilitates detection of exposure of certain fluids to the mechanicalcomponent via changes to properties of the corrosion detection coating(e.g., electrical properties, optical properties, or both), therebyenabling more rapid detection of potential damage to the mechanicalcomponent. For example, as discussed in more detail herein, thecorrosion detection coating may be capable of producing a change inoptical properties, such as a change in color, hue, and/or tone uponexposure to water, other fluids (e.g., H₂S, CO₂, or both), and/or anacid or base, or any combination thereof, over time due to a reactionbetween the water and/or other fluids and the corrosion detectioncoating that causes a change in the oxidation state of the tracers ofthe corrosion detection coating. Further, it is presently recognizedthat the disclosed corrosion detection coating may facilitate detectionof a likelihood that corrosion might occur if a mechanical component isutilized based on the change in the electronic property, the opticalproperty, or both. That is, the disclosed corrosion detection coatingmay be utilized to detect a presence of water before the environmentalconditions reach a magnitude for corrosion to develop. Accordingly, thecorrosion detection coating may help to predict future occurrences ofcorrosion, wherein the corrosion detection coating may be used toprovide a risk assessment and a numerical value indicating a likelihoodof future occurrences of corrosion. For example, the numerical value maybe any percentage value between 0 and 100 percent, a numerical valuebetween 1 to 10, 1 to 100, or 1 to 1000, or some other numerical range.

In some embodiments, the change in optical properties may includeproducing luminescence, among other visual indicators. At least in someinstances, the changes in optical properties may occur in the visiblespectrum. In some embodiments, the corrosion detection coating may becapable of responding (e.g., changing properties in response to certainfluids) while in relatively low temperatures (e.g., approximately up to25° C.) and relatively low concentrations of water (e.g., less thanapproximately 600 ppm H₂O), such as for corrosion detection coatingspositioned at a surface and a top side of completions. In someembodiments, the corrosion detection coating may be capable ofresponding (e.g., changing properties in response to certain fluids)while in relatively high temperatures and relatively high concentrationsof water (e.g., between approximately 25 to 100° C. in Sc CO₂ withgreater than approximately 600 ppm H₂O), such as for corrosion detectioncoatings positioned downhole and in proximity to downhole safety valves.In some embodiments, the corrosion detection coating may be capable ofresponding (e.g., changing properties in response to certain fluids)while in relatively high temperatures (e.g., between approximately 25 to175° C.), such as for corrosion detection coatings positioned atlocations having (or expecting) water condensates at pH less thanapproximately 4.0. It should be noted that the discussion herein relatedto hydrocarbon extraction components is meant to be non-limiting withrespect to materials being extracted. For example, the disclosedtechniques may be applied to fluid extraction components, such as CO₂extraction components, hydrogen gas extraction components, waterextraction components, or any combination thereof, as well as systemsthat may utilize these components (e.g., CO₂ extraction systems,hydrogen gas extraction systems, water extraction systems). In any case,the change in the optical property and/or electrical property may bedetected or measured and utilized to modify operations associated withthe mechanical component, such as causing the mechanical component tostop operating, be replaced, repaired, and/or indicate an estimatedduration for which the mechanical component may continue to be utilizedbefore it should be replaced.

With the foregoing in mind, FIG. 1 illustrates a well closure system 10that may utilize the disclosed corrosion detection coating. In a wellclosure system, one or multiple closure devices 12 may be lowered into awellbore 14 (e.g., installed and anchored within the wellbore 14) priorto certain operations, such as well production. The closure device 12may be lowered into the wellbore 14 as a first installation, to replacea previously installed closure device 12, or to add an additionalclosure device 12. In any case, the closure device 12 is configured tocontrol flow from the reservoir such that it only goes in at thespecific manage points (e.g., perforations, valves, and the like). Forexample, the closure device 12 may block a flow of formation fluid fromreaching a surface located above a geological formation 16 (e.g., viaconduits such as a casing conduit 18 and/or a production tubing 20),which flow may result from high pressure conditions that arise duringwell production. The closure device 12 may include a valve 22, such as asubsurface valve. For example, the valve 22 may include a gate valve, aball valve, a check valve, or any combination thereof. As shown in thisconfiguration of the wellbore 14, the wellbore completion includes acasing conduit 18 and a production casing conduit 20 (e.g., productiontubing) with an annular sealing element 24 (e.g., metal and/orelastomeric seal) that seals an annular space 26 defined between thecasing conduit 18 and the production casing conduit 20. The wellbore 14may include a wellhead 28 at the surface of the well closure system 10that may selectively seal the casing conduit 18 and/or the productioncasing conduit 20.

In the illustrated example of FIG. 1 , the closure device 12 includes avalve housing 30 having a valve 22, an actuation subsystem 32 (e.g., anactuator), and a valve controller 34. The closure device 12 is sealed inthe production tubing by a sealing element so that the fluid may notreach the surface if it does not pass through the valve 22. The valve 22includes a flapper that can switch between an open position to enablefluid flow and a closed position to block the fluid flow. The actuationsubsystem 32 includes a biasing component 36 (e.g., a pressurizationpiston coupled to a spring) to maintain the valve 22 in a defaultposition (e.g., open or closed). The valve controller 34 is configuredto control and/or adjust a position of components of the closure device12 (e.g., the valve 22) via the actuation subsystem 32 to block the flowof formation fluid from reaching the surface or to enable the fluid toflow toward the surface. In certain embodiments, the valve 22 and/or oneor more additional valves may be used to control fluid flow from thesurface to a downhole location, such as by injecting one or more fluids(e.g., CO₂).

It should be noted that the actuation subsystem 32 and the valve housing30 may be configured to operate with or without use of hydraulic orelectrical control lines extending from the surface into the wellbore14. For example, electrical power and/or hydraulic pressure may beprovided from the surface using one or more electrical generators, apower grid, batteries, hydraulic pumps, or a combination thereof.Additionally, or alternatively, the actuation subsystem 32 may bepowered by one or more local power supplies, such as a battery pack, atthe location of the valve 22.

The illustrated embodiment of the closure device 12 includes the valvecontroller 34 that may be utilized to adjust the positon of thecomponents in the valve housing 30. The valve controller 34 controlsand/or adjusts a position of the valve 22 between open and closedpositions (e.g., via the actuation subsystem 32). For example, the valvecontroller 34 may control and/or adjust the valve 22 based on messagesthat are transmitted by a transmitter of a transmitter subsystem 38.

In some embodiments, the transmitter subsystem 38 may receive sensormeasurements (e.g., temperature sensor measurements, pressure sensormeasurements, flow-rate sensor measurements, another suitable parameter,or any combination thereof). The sensor measurements may be directed bysurface sensors, downhole sensors, or completion sensors to thetransmitter subsystem 38 via any suitable telemetry (e.g., viaelectrical signals pulsed through the geological formation 16 or via mudpulse telemetry). In some embodiments, the transmitter subsystem 38 mayreceive inputs from a user interface controlled by an operator. Thetransmitter subsystem 38 may process the sensor measurements and/or userinputs to determine a condition within the wellbore 14 or at the surfaceand determine whether to adjust the position of the valve 22 based onthe condition of the wellbore 14 and/or the surface.

To this end, the transmitter subsystem 38 may be any electronic dataprocessing system that can be used to carry out the systems and methodsof this disclosure. For example, the transmitter subsystem 38 mayinclude a processor 40 which may execute instructions stored in memory42 and/or storage 44. As such, the memory 42 and/or the storage 44 ofthe transmitter subsystem 38 may be any suitable article of manufacturethat can store the instructions. In some embodiments, the memory 42 is atangible, non-transitory, machine-readable-medium that may storemachine-readable instructions for the processor 40 to execute. Thememory 42 may include ROM, flash memory, a hard drive, or any othersuitable optical, magnetic, or solid-state storage medium, or acombination thereof. The memory 42 may store data, instructions, and anyother suitable data. Additionally, the transmitter subsystem 38 mayinclude an input/output (I/O) port 46, which may include interfacescoupled to various components such as input devices (e.g., keyboard,mouse), input/output (I/O) modules, sensors (e.g., surface sensorsand/or downhole sensors), and the like. For example, the I/O port 46 mayinclude a display (e.g., an electronic display) that may provide avisualization, a well log, or other operating parameters of thegeological formation 16, the wellbore 14, or the surface to an operator,for example. In this embodiment, the transmitter subsystem 38 (e.g.,data processing system) has been represented at the well site. However,all or part of the transmitter subsystem 38 (e.g., all or part of theprocessor, the display, the memory, etc.) may be situated remotely fromthe well site and configured to communicate with the well site via anetwork connection. It should be noted that, at least in some instances,all or part of the data processing system may be cloud-based.

While the description above generally relates to a well closure system,it should be noted that the corrosion detection coating may also be usedfor detecting corrosion in components used for other oil and gasoperations, such as midstream operations. FIG. 2 is a flow diagram 48 ofa midstream operation whereby crude oil, natural gas, and naturalliquids (e.g., ethane, propane, and butane) may be transported (e.g.,via vehicles 52 carrying storage tanks) from a well site 50 (e.g., whichmay include a geological closure system 10 as described in FIG. 1 orother well site components such as downhole tools, drills, and the like)to one or more storage tanks 54 or transported to a refinery 56 beforeultimately being transported for distribution 58.

As discussed herein, a corrosion detection coating may be applied to oneor more surfaces of components to facilitate detection of corrosion dueto a presence of certain fluids, such as water in a normally dry fluidlike carbon dioxide or hydrogen, or water in combination with CO₂ orH₂S, an acid or base, or any combination thereof. To facilitate thediscussion of the corrosion detection coating, FIG. 3 is a flow diagramof an embodiment of a process 60 for producing the corrosion detectioncoating 62 (e.g., material coating) on a substrate 64 (e.g., surfaces ofthe valve 22, the casing conduit 18, and other components described withrespect to FIG. 1 , or surfaces of the vehicles 52, the storage tanks54, or other components described with respect to FIG. 2 ) thatfacilitates detection of leaks or corrosion that may be otherwiseundetectable until the machine component is damaged. It should be notedthat the corrosion detection coating 62 may be applied to the insideand/or outside of the substrates 64, which may facilitate detection indifferent applications. For example, providing the corrosion detectioncoating 62 on the outside of the substrate 64 may facilitate detectionof water exposure to the substrate 64 (e.g., a machine component such asa valve) during transportation. Additionally, providing the corrosiondetection coating 62 on the inside of the substrate 64 (e.g., a machinecomponent such as a valve) may facilitate detection of water exposurewhile the machine component is in operation. The steps illustrated inthe process 60 are meant to facilitate discussion and are not intendedto limit the scope of this disclosure, because additional steps may beperformed, certain steps may be omitted, and the illustrated steps maybe performed in an alternative order or in parallel, where appropriate.

To start the process 60, at block 66, one or more tracers 68, polymericmaterials 70 (e.g., monomer units of one or more polymers, such asengineering polymers), and additives 72 may be combined, mixed,dispersed, or otherwise integrated to form a mixture. In someembodiments, the mixture may be dissolved in a solvent such that themixture may be applied to the substrate 64 (e.g., steel, tungstenalloys, or other relatively hard materials used in downhole components)using a spray process.

As discussed in more details herein, the tracers 68 are materialscapable of producing a detectable, measurable, or observable change inat least a portion of the surface or volume in optical properties and/orelectrical properties of the corrosion detection coating 62 uponexposure to one or more fluids, such as water, CO₂, H₂S, an acid, or abase. The tracers 68 may include one or more types of metal particles 74and/or one or more types of inorganic particles 76, each of which may bea micron-sized particle, a nanoparticle, or a larger size particle.

At block 78, the combination of materials (or material composition)formed at block 66 (e.g., including the tracer(s) 68, the polymericmaterial 70, and the additives 72) may be applied, deposited, or coupledto a surface of a substrate 64. For example, in an embodiment where thecombination is dissolved in a solvent, the dissolved combination may beapplied to the surface of the substrate 64 using a spray depositionapplicator. The amount of the combination applied to the substrate 64may produce a suitable thickness for the operation, for example, theamount of the combination may result in a micrometer sized thickness,such as approximately 25 μm, 50 μm, 100 μm, 200 μm, 400 μm, 500 μm, orgreater than 500 μm. In some embodiments, the combination may include at40% by volume, 50% by volume, 60% by volume, 70% by volume, 80% byvolume, 90% by volume, or greater than 90% by volume of the engineeringpolymer and 60% by volume, 50% by volume, 40% by volume, 30% by volume,20% by volume, 10% by volume, or less than 10% of a combination of boththe one or more inorganic particles and the one or more metal particles.In some embodiments, the proportion of the one or more inorganicparticles and the one or more metal particles may include more inorganicparticles than metal particles (e.g., greater than 80% volume ofinorganic particles and less than 20% volume of metal particles, greaterthan 60% volume of inorganic particles and less than 40% volume of metalparticles, greater than 50% volume of inorganic particles and less than50% volume of metal particles). In some embodiments, the proportion ofthe one or more inorganic particles and the one or more metal particlesmay include more metal particles than inorganic particles (e.g., greaterthan 80% volume of metal particles and less than 20% volume of inorganicparticles, greater than 60% volume of metal particles and less than 60%volume of inorganic particles, greater than 50% volume of metalparticles and less than 50% volume of inorganic particles). At block 80,the coating may be treated to form the corrosion detection coating 62.In general, treating the coating may include suitable processes forpolymerizing the engineering polymer and/or dissolving any solvent usedin the coating. For example, at least in some embodiments, the coatingmay be treated with light (e.g., ultraviolet (UV)) and/or thermallytreated for a predetermined time period. The time period may be 1 hour,5 hours, 10 hours, 20 hours, or greater than 20 hours. The corrosiondetection coating 62 is generally a material coating composed of one ormore tracers 68 and additives 72 dispersed within polymeric material 70that have been cured or treated (e.g., a cured polymeric material).

The tracers 68 may include nanoparticles having an average diametergreater than 25 nm, greater than 50 nm, greater than 100 nm, greaterthan 200 nm, or greater than 250 nm. The tracers 68 may includemicron-sized particles having an average diameter of greater than 1 μm,greater than 2 μm, greater than 10 μm, greater than 50 μm, greater than75 μm, or greater than 80 μm. In some embodiments, the tracers 68 mayinclude both micron-sized and nanoparticles, and as such, the tracers 68may have a range of particle sizes between 10 nm and 200 μm, 25 nm and100 μm, 50 nm and 75 μm, or 100 nm and 50 μm.

In some embodiments, the corrosion detection coating 62 may includemetal particles 74 and/or inorganic particles 76. For example, thecorrosion detection coating 62 may include a combination or mixture ofone or more metal particles 74 and one or more inorganic particles 76.In any case, the metal particles 74 and/or inorganic particles 76 aregenerally capable of producing the detectable change in the opticalproperty and/or electrical property based on a reaction between one ormore fluids (e.g., water, water and H₂S, water and CO₂, water and anacid, water and a base) and the particles (e.g., the metal particlesand/or inorganic particles) of the material coating. In someembodiments, the tracers 68 may be insoluble in water, acidic water, orbasic water. In some embodiments, the tracers 68 may be soluble in watersuch that the tracers 68 may dissolve and cause a darkening in thecorrosion detection coating 62 due to change (e.g., increase ordecrease) in opacity resulting from the tracer 68 dissolving.Alternatively, the tracers 68 may cause a lightening in the corrosiondetection coating 62 due to the corrosion detection coating 62 becomingless opaque after reacting with fluids.

The metal particles 74 may include metals or metal alloys. For example,the metal particles 74 may include transition metals, such as one ormore of copper, zinc, nickel, iron, cobalt, cadmium, manganese,titanium, vanadium, zirconium, chromium, or any combination thereof. Insome embodiments, the metal particles 74 may include main group metals,such as one or more of aluminum, tin, bismuth, boron, silicon, or anycombination thereof. In some embodiments, the metal particles 74 mayinclude alloys of transition metals, main group metals, or anycombination thereof. For example, the metal particles 74 may includecopper alloys, such as one or more of Cu—Ni, Cu—Zn, Cu—Sn, or Cu—Ag. Asanother non-limiting example of alloys, the metal particles 74 mayinclude zinc alloys, such as one or more of Zn—Cu, Zn—Al, Zn—Co, orZn—Al—Mg. It should be noted that particles of zinc alloys may be moredurable (e.g., having a relatively greater mechanical hardness) ascompared to copper particles. As another non-limiting example of alloys,the metal particles 74 may include bismuth alloys, such as one or moreof Bi—Sn, Bi—Sn—Zn, or Bi—In. It should be noted that these metals maybe less reactive that certain transition metal alloys, but maynonetheless still discolor in the presence of H₂S and water. Examplecompositions of certain metals and metal alloys are presented in Table1.

TABLE 1 Examples of metals and metal alloys that may be employed asmetal particles. Name & Family Typical composition Cu powder 99 wt. % CuCu—Ni (cupronickel) Reacts with H₂S; up to 35 wt. % Ni is common alongalloys Cu—Zn (brass) 60 wt. % Cu-40 wt. % Zn Cu—Sn (Phosphorus Bronze) 7wt. % Sn-0.35 max P Cu—Ni Cu-16.5-19.5 Ni Cu—Ag Relatively high cost andmay include <1 wt. % Ag Zn Reacts with sulfur to produce ZnS thatluminesce Zn—Cu, Zn—Al, More durable than just Cu Zn—Al—Mg, Zn—Co Bi,Bi—Sn, Bi—Sn—Zn, Highly inert, but may discolor Bi—In in the presence ofH₂S

The inorganic particles 76 may include metal oxides, sulfides,phosphides, phosphates, and/or carbonates. For example, the metal oxidesmay include transition metal oxides, such as one or more of nickeloxide, chromium oxide, titanium oxide, copper (i) oxide, red iron oxide,black iron oxide yellow oxide, nickel oxide, molybdenum trioxide,cadmium oxide, or any combination thereof. The metal oxides may includemain group metal oxides, such as one or more of magnesium oxide,aluminum oxide, tin oxide, calcium oxide, or any combination thereof.The metal sulfides may include transition metal sulfides, such as one ormore of green zinc sulfide, white zinc sulfide, copper sulfide, ironsulfide, cadmium sulfide, or any combination thereof. The metal sulfidesmay include main group oxides such as tin disulfide. The metalphosphides may include transition metal phosphides, metal phosphides, ora combination thereof, such as iron phosphide or gallium phosphide. Themetal carbonates may include transition metal carbonates, such as one ormore of cobalt carbonate, nickel carbonate, coper carbonate, or anycombination thereof. The metal carbonates may include main groupcarbonates, such as calcium carbonate, lithium carbonate, and the like.Example compositions of certain inorganic particles are presented inTable 2.

TABLE 2 Examples of oxides, sulfides, phosphides, and carbonates thatmay be employed as inorganic particles. Water Color Name & FamilyThermal stability solubility Green Nickel oxide, NiO Tm ~1955° C.Negligible Chrome oxide, Cr₂O₃ Tm ~2435° C. Insoluble Nickel carbonate,NiCO₃ Decomposition: Negligible ~205° C. Copper carbonate, CuCO₃ Tm~200° C. Soluble Zinc sulfide, ZnS (pure) Tm ~1850 

 ° C. Negligibly soluble White Titanium oxide, TiO₂ Tm ~1843° C.Insoluble Magnesium oxide, MgO Tm ~2852° C. Soluble in acids Aluminumoxide, Al₂O₃ Tm ~2072° C. Insoluble Tin oxide, SnO₂ Tm ~1630° C.Insoluble Calcium carbonate, CaCO₃ Tm ~1339° C. Negligible solubleCalcium oxide, CaO Tm ~2572° C. Soluble Lithium carbonate, Li2CO3 Tm~723° C., Highly decomposes soluble at ~1300° C. in water Zinc oxide,ZnO (pure) Tm ~1974° C. (decomposes) Zinc sulfide, ZnS Tm ~1850° C.Negligible Red Copper oxide, Cu₂O Tm ~1232° C Insoluble Iron oxide, redTm ~1539° C. Insoluble Purple Cobalt carbonate, CoCO₂ Tm ~427° C.,Insoluble decomposes to Co₂O at ~140° C. Blue Na₆Al₆Si₆O₂₄S₄ ColorStable up to ~300° F. CaCO₃ + C₂N₈H₁₆Cu Color Stable up to ~330° F.Si₄O₁₀(OH)₂Mg₃—Co₃Ca—Al Color Stable up to ~330° F. C₆Fe₂KN₆ + TiO₂Color Stable up to ~300° F. CuAl₆(PO₄)₄(OH)₈•4H₂O Tm >700° C. SolubleBlack Cobalt oxide Tm ~1933° C. Insoluble Nickel oxide, Ni₂O₃ DecomposesNegligible at ~600° C. soluble Iron oxide, black Tm ~1539° C. Coppersulfide, CuS Tm >500° C. Insoluble Iron sulfide, FeS Tm ~1194° C.Negligible Yellow Cadmium oxide Tm >900° C. Slightly soluble Cadmiumsulfide, CdS Tm ~1750° C. Insoluble Tin disulfide, SnS₂ Tm ~600° C.Insoluble Iron oxide, yellow Tm ~1539° C.

In some embodiments, the inorganic particle 76 or metal particle 74 maybe selected to have a particular color or result in particular color oroptical property upon exposure to fluids and/or pH. For example, oxides,carbonates, and sulfides that are generally white, yellow, and red(e.g., as indicated by Table 2) may produce a visible darkening or colorchange in the presence of water and/or presence of H₂S. For example, theinorganic particle 76 may be white in an initial oxidation state, suchas tin oxide, which is water insoluble and amphoteric (e.g., dissolvesin acids and bases), SnO₂, boric oxide (i.e., B₂O₃), calcium oxide(i.e., CaO), or magnesium oxide (i.e., MgO), or any combination thereof.It should be noted that B₂O₃ may absorb water relatively slowly to formboric acid, and produce a visible change in opacity and/or color with asmall amount of B₂O₃. As such, a corrosion detection coating 62including inorganic particles 76 such as tin oxide, SnO₂, boric oxide,calcium oxide, or magnesium oxide may be capable of producing adetectable change in optical properties due to a reaction between theinorganic particles and acidic fluids. As another non-limiting exampleof a white inorganic particle 76, zinc oxide may display a color changein the presence of H₂S or a yellow reversible change when heated in air.As such, a corrosion detection coating 62 including zinc oxide may becapable of producing a detectable change in optical properties (e.g.,based on a magnitude of the change in color from white) due to areaction between ZnO and H₂S.

With respect to examples of yellow inorganic particles 76, it is notedthat bismuth oxide (i.e., Bi₂O₃) may produce different colors resultingbetween reactions with CO₂ and/or temperature. As such, a corrosiondetection coating 62 including bismuth oxide may be capable of producinga detectable change in optical properties due to a reaction betweenbismuth oxide and CO₂. With respect to examples of red inorganicparticles 76, it is noted that iron oxide and copper oxide may producedifferent colors resulting between reactions with water of different pHand/or H₂S. As such, a corrosion detection coating 62 including ironoxide and/or copper oxide may be capable of producing a detectablechange in optical properties due to a reaction between iron oxide and/orcopper oxide and water of different pH and/or H₂S. In any case, themagnitude of the change in the optical properties from white or yellowto a different color may be used to determine an amount of exposure of asubstrate 64 of a mechanical component to certain fluids, therebyenabling rapid detection of components that may soon become or arealready compromised.

In some embodiments, the reaction between fluids and metal particles 74and/or inorganic particles 76 may cause the metal particles 74 and/orinorganic particles 76 to corrode, resulting in a color change. Forexample, certain oxides may react in alkali conditions, such as iron,which corrode to form iron hydroxide.

In some embodiments, the reaction between fluids and metal particles 74and/or inorganic particles 76 may cause the metal particles 74 and/orinorganic particles 76 to undergo a brightening due to the presence ofwater. For example, the brightening of a dark pigment, such as Ni₂O₃,included in a corrosion detection coating 62 may indicate that amechanical component coated with the corrosion detection coating 62 hasbeen exposed to water due to the reaction between water and Ni₂O₃.

As another example, the inorganic particle 76 may gain an opticalproperty in the presence of the fluids. For example, Zn may be used asthe tracer 68, which forms ZnS in the presence of H₂S, and thus mayluminesce. Luminesce or other optical property resulting from the changein the composition of the tracer 68 (e.g., Zn changing to ZnS) mayfacilitate early detection of exposure of the substrate 64 coated withthe corrosion detection coating 62 to flow or corrosion.

In general, the polymeric material 70 are subunits (e.g., monomers) of apolymer having mechanical properties, such as one or more of heatresistance, mechanical strength, rigidity, chemical stability,self-lubrication, or any combination thereof, suitable for maintainingthe structure of the material coating during certain oil and gasoperations described herein. In some embodiments, the polymeric material70 may include engineering polymers. For example, the polymeric material70 may have an operating temperature up to at least 200° C., at least250° C., at least 300° C., at least 350° C., or greater than 350° C. Thepolymeric material 70 may include one or more of polyether ether ketone(PEEK), polyetherketone (PEK), other polyaryletherketone (PAEK)polymers, polyphenylene sulfide, nylon polymers, epoxy polymers, or anycombination thereof.

In some embodiment, the material coating may include one or moreadditives 72 that generally improve one or more of the hardness (e.g.,hardening additives), improve the lubrication (e.g., lubricativeadditives), or modify (e.g., increase or decrease) the permeability(e.g., permeability control additives) of the corrosion detectioncoating, thereby controlling the rate at which the tracers react withfluids. In some embodiments, the additives 72 may include carbonadditives graphene, nanotubes, graphite, fullerene, or any combinationthereof. At least in some instances, the carbon additives may contributeto the electrical properties of the corrosion detection coating. Forexample, it is recognized that one or more layers of graphene mayimprove the conductance of the corrosion detection coating, which mayfacilitate the measurement of the electrical properties of the corrosiondetection coating. In some embodiments, the additives 72 may includeceramic hardeners, such as alumina (Al₂O₃) and titanium (ii) oxide(TiO₂).

To illustrate how the corrosion may be detected, FIG. 4 is a diagram ofan embodiment of a surface monitoring system 82 configured to detect achange in the optical and/or electrical properties of the corrosiondetection coating 62. For example, the surface monitoring system 82 mayinclude one or more of an optical monitoring system 84, an electricalmonitoring system 86, and/or a visual inspection system 88.

As discussed with respect to FIG. 3 , the corrosion detection coating 62is generally a material coating composed of one or more tracers 68dispersed within an polymeric material 70 that has been treated orcured. In general, and as discussed in more detail herein, the tracers68 are materials capable of producing a detectable, measurable, orobservable change in at least a portion 90 of the surface or volume inoptical properties and/or electrical properties of the corrosiondetection coating 62 upon exposure to one or more fluids, such as water,CO₂, H₂S, an acid, or a base. As referred to herein, a “change in anoptical property” may include one or more of a change in a color, a hue,a reflectance, a transmission, a polarization, an absorption, or aluminescent capability of a material. As referred to herein, a “changein an electrical property” may include a change in an impedance of amaterial, which may be measureable by a change in an inductance, acapacitance, and a resistance. In some embodiments, the tracers includematerials capable of producing the detectable change in the opticalproperty and/or electrical property based on a combination of fluids,such as water and CO₂, water and H₂S, water and an acid, or water and abase.

The optical monitoring system 84 generally includes one or more opticalsensors 92 to measure or detect the change in the optical properties ofthe corrosion detection coating 62 due to changes on a surface (e.g.,the portion 90) of the corrosion detection coating 62. In someembodiments, the optical sensors 92 may include cameras, lightdetectors, and other suitable devices capable of generating an image orspectrum indicative of the composition of the corrosion detectioncoating 62. For example, the optical sensors 92 may include a lightsource to emit light at one or more frequencies and a light detectorpositioned to receive the light reflected or transmitted through thecorrosion detection coating 62 and generate sensor data.

The electrical monitoring system 86 generally includes one or moreelectrical sensors 94 that measure or detect the change in theelectrical properties of the corrosion detection coating 62 due tochanges on a surface (e.g., the portion 90) of the corrosion detectioncoating 62. In some embodiments, the electrical sensors 94 may includeelectrical property sensors, multimeters, and other suitable devicescapable of measuring a resistance of the corrosion detection coating 62,a change in current flowing through the corrosion detection coating 62,a change in the dielectric constant of the corrosion detection coating62, and the like, that are indicative of the composition of thecorrosion detection coating 62.

The visual inspection system 88 generally includes a data input device96 where visual data may be input indicative of a change in the opticalproperties of the corrosion detection coating 62. For example, thechange may be a binary indication (e.g., “0” for no change, “1” for achange) or may be indicative of a magnitude of change (e.g., a color ofthe surface (e.g., the portion 90), an area of the surface, a tint ofthe surface, a hue of the surface, and the like).

In any case, the sensor data (e.g., generated by the optical sensor(s)92 and/or the electrical sensor(s) 94) and/or the visual data (e.g.,from the visual inspection system 88) may be output to a computingdevice 98 (e.g., computer) having a processor 100, which may executeinstructions stored in memory 102 and/or storage media, or based oninputs provided from a user via the input/output (I/O) device 104. Thememory 102 and/or the storage media may be read-only memory (ROM),random-access memory (RAM), flash memory, an optical storage medium, ora hard disk drive, to name but a few examples. For example, inoperation, the processor 100 may receive sensor data and/or the visualdata, determine that the visual properties or electrical properties ofthe corrosion detection coating 62 have changed above a thresholdindicating a potential of exposure to water and H₂S, CO₂, or anycombination thereof, and send an alert or suitable control signals totake a corrective action.

In some embodiments, the processor 100 of the surface monitoring system82 may send suitable control signals to a controller 106 (e.g., anexternal controller) of a fluid handling system 107. In general, thefluid handling system 107 refers may include machine components ordownhole components that control one or more oil and gas operations. Forexample, the fluid handling system 107 may include systems forretrieving fluids oil, natural gas, water and/or injecting fluids suchas water and/or CO₂. In embodiments where the fluid handling system 107is expected to retrieve or inject fluids that may be detectable bycertain embodiments of the corrosion detection coating 62, the materialsof the corrosion detection coating 62 may be selected such that thecorrosion detection coating 62 facilitates detection of unexpectedfluids. For example, in an embodiment where the fluid handling system107 is injecting CO₂, the corrosion detection coating 62 may beconfigured to detect H₂O as it is recognized that H₂O (e.g., anunexpected or undesirable fluid) in combination with CO₂ may corrosionof the machine components of the fluid handling system 107.

In the illustrated embodiment, the fluid handling system 107 includes ahydrocarbon extraction system 108 and/or a sequestration system 109, orother suitable electronic device. For example, the hydrocarbonextraction system 108 may include a wellhead, a casing head, a tubinghead, a frac head, a Christmas tree having various valves and flowcontrol equipment, a blowout preventer, tubing, a chemical injectionsystem, or any combination thereof. For example, the hydrocarbonextraction system 108 may include the transmitter subsystem 38 and thewell closure system 10 described in FIG. 1 . The sequestration system109 may include suitable components (e.g., valves, packers, pumps,wellheads, tubes, pipes, couplings, and other components along downholetubulars and downhole jewelry) for performing sequestration operations,such as CCS as described herein. As such, the suitable control signalmay cause the transmitter subsystem 38 to transmit a control signal thatcauses a valve 22 to modify a position (e.g., open or close), a drill tohalt operation, and the like. As another non-limiting example, themineral extraction system 108 may include vehicles 52 (e.g., that assisttransporting the extracting material) transporting storage tanks 54, asdiscussed in FIG. 2 . As such, the suitable control signal may generatean alert (e.g., via a computing device of a driver or other user)indicating that a storage tank 54 having one or more surfaces coatedwith the corrosion detection coating 62 may have been exposed to one ormore fluids (e.g., indicating an amount of water present in a fluid thatis expected to be dry and a leak), and thus, may need to be replaced orreceive maintenance.

In this way, by enabling the surface monitoring system 82 to monitor andcontrol operation of a fluid handling system 107, the surface monitoringsystem 82 may be utilized in maintenance or machine health monitoringoperations. That is, the surface monitoring system 82 may be capable ofreceiving data (e.g., the sensor data, the visual data, or both), makinga determination about a state or condition of the corrosion detectioncoating 62 (e.g., whether the corrosion detection coating 62 has beenexposed to an amount of water and other fluids above a threshold), andoutputting control signals or alert that may modify the operation of thefluid handling system 107, such as halting operations, alerting a userthat a component including the corrosion detection coating 62 needs tobe replaced, and the like. Additional details with regards to monitoringand controlling operation of equipment (e.g., the mineral extractionsystem 108) are discussed in more detail with respect to FIG. 11 .

The controller 106 associated with the fluid handling system 107includes a processor 110, which may execute instructions stored inmemory 112 and/or storage media 44, or based on inputs provided from auser via the input/output (I/O) device 114. The processor 110 mayexecute instructions stored in memory 112 and/or storage media, or basedon inputs provided from a user via the input/output (I/O) device 114.The memory 112 and/or the storage media 44 may be read-only memory(ROM), random-access memory (RAM), flash memory, an optical storagemedium, or a hard disk drive, to name but a few examples. At least insome instances, the processor 100 of the computing device 98 of thesurface monitoring system 82 may send the control signals directly tothe fluid handling system 107 instead of sending control signals to anexternal processor (e.g., the processor 110 of the controller 106).

To illustrate one embodiment of the corrosion detection coating 62, FIG.5 shows a cross section of an embodiment of the corrosion detectioncoating 62 having multiple materials dispersed within the curedpolymeric material 115. In the illustrated embodiment, metal particles74 and inorganic particles 76 are dispersed within the cured polymericmaterial 115. It should be noted that the combination of materials(e.g., the metal particles 74 and inorganic particles 76) shown in FIG.5 is non-limiting. That is, in some embodiments, one or more types ofmetal particles 74, one or more types of inorganic particles 76, and/orone or more types of additives may be dispersed within the curedpolymeric material 115.

In some embodiments, one or more of the steps of the process 60 may berepeated. For example, steps 66, 78, and 80 may be repeated to formmultiple layers (e.g., two, three, four, or more) of the corrosiondetection coating 62. In some embodiments, the tracers 68, the polymericmaterial 70 (e.g., used to produce a cured polymeric material 115),and/or the additives 72 may differ such that the composition of a secondlayer is different than a first layer (e.g., applied in a previousstep). At least in some instances, one or more materials may bedeposited in between the layers of the corrosion detection coating 62,such as conductive metal films. Such embodiments where one or more stepsof the process 60 may be repeated or steps may be added are discussedwith respect to FIGS. 6-8 . In some embodiments, multiple corrosiondetection coatings 62 may be used to sense in stages, a presence and/orconcentration of fluids. For example, the multiple corrosion detectioncoatings 62 may vary based on an expected temperature range associatedwith a region where the component is being utilized. That is, componentsbelow a valve (e.g., further from the surface) may have a first expectedtemperature range and components above the value (e.g., closer to thesurface) may have a second expected temperature range. Accordingly, thematerials (e.g., the metal particles 74, the inorganic particles 76, theadditives 72, and the polymeric material 70) may be selected such thatthe material may be unreactive in the respective temperature ranges andreactive when the respective expected temperature ranges are in anunexpected temperature range, pH, pressure, or any combination thereof.

To illustrate another embodiment of the corrosion detection coating 62,FIG. 6 shows a cross section of an embodiment of a corrosion detectioncoating 62 having multiple layers (e.g., a first layer 116 and a secondlayer 118). In the illustrated embodiment, the first layer 116 includesmetal particles 74 a and inorganic particles 76 a are dispersed withinthe cured polymeric material 15 a. The second layer 118 includes metalparticles 74 b and inorganic particles 76 b are dispersed within thecured polymeric material 115 b. It should be noted that the combinationof materials (e.g., the metal particles 74 a, 74 b and inorganicparticles 76 a, 76 b) shown in FIG. 6 is non-limiting. That is, in someembodiments, multiple types of metal particles 74, multiple types ofinorganic particles 76, or additives may be dispersed within the curedpolymeric material 115.

In some embodiments, a substrate underlayer 120 may be applied to asurface 122 of the substrate 64 prior to applying the corrosiondetection coating 62, as shown in FIG. 7 . The substrate underlayer 120may improve binding of the corrosion detection layer 62 to the substrate64 and/or provide protection to the surface 122 of the substrate 64 dueto mechanical wear (e.g., the substrate underlayer 120 may have arelatively higher mechanical hardness than the substrate 64). Thesubstrate layer 120 may include one or more multiple layers of acarbide, a nitride, a boride, which may be applied by techniques such asthermal spray or thermal diffusion. The thickness 121 of the substratelayer 120 may be relatively thin (e.g., approximately 100 mm,approximately 90 mm, approximately 80 mm, approximately 75 mm, less than75 mm). In some embodiments, the substrate under layer 120 may be ametallic plating, such as Ni (Ni—P, Ni—W, Ni—Co—P), Co (Co—P). Thethickness 121 of the substrate layer 120 may be less than approximately100 μm, less than approximately 90 μm, less than approximately 80 μm,less than approximately 75 μm, less than approximately 50 μm. It shouldbe noted that providing the substrate underlayer 120 may improve themechanical wear resistance of mechanical components, such as tools,while the corrosion detection coating 62 may be used for maintenancemonitoring operations, such as determining whether a mechanicalcomponent coated with the substrate underlayer 120 and the corrosiondetection coating 62 has been exposed to fluids that may damage themechanical component, but may otherwise be difficult to detect prior tothe mechanical component being rendered inoperable due to damage.

In some embodiments, multiple layers of the corrosion detection coating62 may be applied to a substrate 64 and an intervening layer of amaterial other than the corrosion detection coating 62 may be appliedbefore application of a second layer or third layer, as shown in FIG. 8. For example, a conductive layer 124 may dispersed between the firstlayer 116 and the second layer 118. In general, the conductive layer 124may be a wire, conductive tape, metal particles, or other suitablematerials capable of conducting current through the layers. For example,the conductive layer 124 may be graphene, copper, gold, and otherconductive materials. The area coverage of the conductive layer (e.g.,percent area of a cross section 125) may be less than approximately 10%,less than approximately 9%, less than approximately 8%, less thanapproximately 7%, less than approximately 6%, or less than approximately5%.

FIG. 9 is a schematic diagram of an embodiment of the electricalmonitoring system 86 of the surface monitoring system 82, in accordancewith the present technique. The embodiment of the electrical monitoringsystem 86 illustrated in FIG. 9 includes electrodes 126 electricallycoupled to the corrosion detection coating 62. A current may be appliedto the corrosion detection coating 62. In certain embodiments, thecircuit 130 includes an electrical property sensor 128 (e.g., electricalproperty sensor 94), such as a multi-meter, communicatively coupled tothe processor 100 of the computing device 98. The electrical propertysensor 128 provides suitable signals to indicate changes in thecomposition of the corrosion detection coating 62 (e.g., due to areaction between the tracers 68 and fluids that results in a change inthe oxidation state of the metals or cations of the tracers 68),resulting in a change in the electrical properties of the circuit 130.Based on the change in the electrical properties of the circuit 130, theprocessor 100 of the computing device 98 may determine the change in thecomposition of the corrosion detection coating 62.

FIG. 10 is a schematic diagram illustrating an embodiment of the opticalmonitoring system 84 of the surface monitoring system 82, in accordancewith the present technique. More specifically, the optical monitoringsystem 84 illustrated in FIG. 10 optically detects or measures opticalproperties of corrosion detection coating 62. The illustrated embodimentincludes a light source 132 and a light detector 134 (e.g., an opticalsensor 92). The light source 132 generates emitted light 136 having anintensity that is detected by the light detector 134. During operationof the embodiment of the optical monitoring system 84 illustrated inFIG. 10 , emitted light 136 from the light source 132 that interactswith the corrosion detection coating 62 may result in modified light138. Modified light 138 may result from emitted light 136 that isscattered, absorbed, reflected, or absorbed and subsequently reemitted,for example, through fluorescence or Raman. The modified light 138 mayhave an intensity that differs from the intensity of the emitted light,which is proportional to a change in the composition of the corrosiondetection coating 62 (e.g., material coating), such as by oxidation ofmetals of the metal particles. In certain embodiments, no modified light138 is detected by the light detector 134, indicating that the change inthe composition of the corrosion detection coating 62 was sufficientenough to block or prevent the emitted light 136 from reaching the lightdetector 134. Alternatively, if the corrosion detection coating 62includes a material that reflects a minimal amount of light in anunreacted (e.g., unexposed) state, then no modified light 138 beingdetected by the light detector 134 may indicated that the corrosiondetection coating 62 has not been exposed to fluids. The light detector134 is disposed in suitable positions downstream from the light source132 to detect a change in the emitted light 136 based on the change inthe composition of the corrosion detection coating 62.

To illustrate operation of the embodiments of components of the surfacemonitoring system 82 described in FIGS. 4, 9 and 10 , FIG. 11illustrates an embodiment of a process for generating a corrosiondetection output, such as an alert or a control signal to modifyoperation of components of a fluid handling system 107. Although themethod 140 is described as being performed by the computing device 98,it should be noted that any suitable computer or processor-based devicecapable of communicating with other components of the surface monitoringsystem 82 may perform the disclosed method 140 including, but notlimited to, the controller 106, the transmitter subsystem 38, and thelike.

At block 142, the surface monitoring system 82 may acquire opticalproperty data and/or electrical property data using the opticalmonitoring system 84, the electrical monitoring system 86, and/or thevisual inspection system 88. For example, in an embodiment where thesurface monitoring system 82 includes the electrical monitoring system86, the surface monitoring system 82 may activate the electrodes 126 tocause the electrodes 126 of the electrical monitoring system 86 toinduce a current (e.g., by applying a voltage) across the corrosiondetection coating 62 and the electrical monitoring system 86 may acquiredata indicative of the electrical property of the corrosion detectioncoating 62 based on the current provided to the one or more corrosiondetection coating 62. For example, the surface monitoring system 82 maydetermine a magnitude of the change in the electrical property (e.g.,based on a relative change). At block 144, the surface monitoring system82 may determine whether the substrate 64 has been exposed to fluids,needs maintenance, or needs to be replaced, based on the electricalproperty data, optical property data, or the input data from the visualinspection system 88. For example, the surface monitoring system 82 maydetermine a color, a position of a peak in an optical spectrum of thecorrosion detection coating 62, a change in resistance, and/or otherproperties as discussed herein, indicative of exposure of a mechanicalcomponent having the corrosion detection coating 62 to one or morefluids, such as water, H₂S, and CO₂. In some embodiments, the surfacemonitoring system 82 may determine a magnitude of the change in color.

As one non-limiting example of a use case, the surface monitoring system82 may acquire optical property data of a corrosion detection coating 62including a copper oxide (e.g., the inorganic particle 76) that haspotentially been oxidized due to exposure to fluids as discussed herein.The optical property data may be an image of a portion of the corrosiondetection coating 62 that includes an area (e.g., the portion 90) havinga different color than a remaining area of the corrosion detectioncoating 62. In some embodiments, the surface monitoring system 82 maydetermine the substrate 64 has been exposed to fluids if the portion 90of the corrosion detection coating 62 has a pixel value (e.g., RGB) of aparticular color indicating that at least a portion of the copper in theportion 90 has oxidized. Additionally or alternatively, the surfacemonitoring system 82 may determine that the substrate 62 has beenexposed to fluids if the dimensions of the portion 90 having a differentcolor that the remaining area of the corrosion are above a dimension orarea threshold. Additionally or alternatively, the surface monitoringsystem 82 may determine that the substrate 62 has been exposed to fluidsif the brightness (e.g., white pixel value exceeds a background whitepixel value threshold. In any case, the surface monitoring system 82 maycompare the detected color, the detected dimensions of the portion 90,the white pixel value, or any combination thereof, to a reference colorvalue (e.g., an RGB value indicating a color of the corrosion detectioncoating 62 including the inorganic particles 76 and metal particles 74),a reference area (e.g., a previously detected portion 90 showingoxidation or a threshold dimension), or a reference white or black pixelvalue stored in a memory (e.g., the memory 102) and determine adiscrepancy between the detected value and the reference value. If thediscrepancy exceeds a threshold (e.g., 10%, 20%, 30%, 40%, 50%, 60%,70%, 80%, 90%, 100%), the surface monitoring system 82 may determine thesubstrate 64 has been exposed to fluids and proceed to block 146.

At block 146, the surface monitoring system 82 may generate a damageoutput (e.g., a mechanical component damage output and/or asequestration component damage output). In general, the damage outputmay include an audible and/or visual alert (e.g., a notificationdisplayed on a computing device, such as a laptop, mobile device,tablet, or otherwise) or cause a component of the mineral extractionsystem 108 (e.g., as discussed in FIG. 4 ) or the sequestration system109 to modify operation. For example, the damage output may be a controlsignal or activation signal that causes a device utilizing themechanical component coated with the corrosion detection coating 62 tostop operating or change operation or position. As another non-limitingexample, the control signal may cause a drill to stop drilling, a valveto open or close, and/or a fluid flow rate to change. In someembodiments, the damage output may be an indication or alert displayedon a computing device, indicating a likelihood that a mechanicalcomponent (e.g., a fluid handling component, a mineral extractioncomponent, a hydrocarbon extraction component, a sequestrationcomponent, or any combination thereof) has been exposed to fluids. Insome embodiments, the notification may indicate a magnitude of theexposure (e.g., based on the change in the optical properties orelectrical properties). For example, the alert may warn a user that themechanical component was likely damaged as well as the extent of thedamage (e.g., determined based on a magnitude change or the location ofthe change in optical and/or electrical properties) and/or a time periodwhen the vehicle was likely damaged. In some embodiments, the surfacemonitoring system 82 may determine an estimated time period forsubsequent use of the mechanical component (e.g., the mineral extractioncomponent, the hydrocarbon extraction component, the sequestrationcomponent, or any combination thereof) coated with the corrosiondetection coating 62 prior to inspection, repair, or replacement. Forexample, the surface monitoring system 82 may use a reference table(e.g., storing relationships between a magnitude of exposure and a timefor replacement or maintenance) stored in a memory and the magnitude ofthe exposure to determine the estimate time period. As such, the surfacemonitoring system 82 may include the estimated time period in thenotification or alert. This written description uses examples todisclose the subject matter, including the best mode, and also to enableany person skilled in the art to practice the subject matter, includingmaking and using any devices or systems and performing any incorporatedmethods. The patentable scope of the subject matter is defined by theclaims and may include other examples that occur to those skilled in theart. Such other examples are intended to be within the scope of theclaims if they have structural elements that do not differ from theliteral language of the claims, or if they include equivalent structuralelements with insubstantial differences from the literal language of theclaims.

The techniques presented and claimed herein are referenced and appliedto material objects and concrete examples of a practical nature thatdemonstrably improve the present technical field and, as such, are notabstract, intangible or purely theoretical. Further, if any claimsappended to the end of this specification contain one or more elementsdesignated as “means for [perform]ing [a function] . . . ” or “step for[perform]ing [a function] . . . ”, it is intended that such elements areto be interpreted under 35 U.S.C. 112(f). However, for any claimscontaining elements designated in any other manner, it is intended thatsuch elements are not to be interpreted under 35 U.S.C. 112(f).

1. A material composition, comprising one or more polymeric materials;one or more inorganic particles comprising oxides, carbonates, sulfides,or any combination thereof; one or more metal particles configured toproduce a detectable change in an electrical property or an opticalproperty based on a reaction with at least one of H₂O, CO₂, or H₂S; andwherein the one or more inorganic particles and the one or more metalparticles are dispersed within the one or more polymeric materials. 2.The material composition of claim 1, wherein the material compositioncomprises hardening additives, lubricant additives, permeability controladditives, or any combination thereof.
 3. The material composition ofclaim 1, wherein the one or more polymeric materials comprise polyetherether ketone (PEEK), polyetherketone (PEK), polyphenylene sulfide, orany combination thereof.
 4. The material composition of claim 1, whereinthe one or more inorganic particles are configured to produce thedetectable change in the optical property based on a reaction with H₂Sand H₂O, wherein the one or more inorganic particles comprise at leastone of zinc oxide, iron oxide, copper oxide, or cadmium oxide.
 5. Thematerial composition of claim 1, wherein the one or more inorganicparticles are configured to produce the detectable change in the opticalproperty based on a reaction with CO₂ and H₂O, wherein the one or moreinorganic particles comprise a bismuth oxide.
 6. The materialcomposition of claim 1, wherein the one or more inorganic particles areconfigured to produce the detectable change in the optical propertybased on a reaction with H₂O, wherein the one or more inorganicparticles comprise B₂O₃.
 7. The material composition of claim 1, whereinthe detectable change in the optical property comprises a darkening or abrightening of the material composition.
 8. The material composition ofclaim 1, wherein the one or more metals comprise copper or copperalloys, zinc or zinc alloys, bismuth or bismuth alloys, or anycombination thereof.
 9. The material composition of claim 1, wherein thematerial composition comprises at least 40% polymer by volume and lessthan or equal to 60% of the one or more inorganic particles and the oneor more metal particles.
 10. The material composition of claim 1,comprising a material coating having the material composition.
 11. Thematerial composition of claim 1, comprising a downhole component thatincludes the material composition at least on a surface of the downholecomponent.
 12. The material composition of claim 11, wherein a thicknessof the material coating is greater than or equal to 25 microns.
 13. Thematerial composition of claim 10, comprising a second material coatinghaving a second material composition, the second material compositionhaving differences in the one or more polymeric materials, the one ormore inorganic particles, and/or the one or more metal particles. 14.The material composition of claim 13, comprising an electricallyconductive material disposed between the material coating and the secondmaterial coating.
 15. A method, comprising: dispersing one or moreinorganic particles into one or more polymeric materials, wherein theone or more inorganic particles comprise oxides, carbonates, sulfides,or any combination thereof; dispersing one or more metal particles intothe one or more polymeric materials, wherein the one or more metalparticles, wherein the one or more metal particles are configured toproduce a detectable change in an electrical property or an opticalproperty based on a reaction with at least one of H₂O, CO₂, or H₂S, andwherein a material composition comprises the one or more polymericmaterials, the one or more inorganic particles, and the one or moremetal particles.
 16. The method of claim 15, comprising applying acoating of the material composition onto a surface of a component of ahydrocarbon extraction or sequestration system.
 17. The method of claim16, wherein applying the coating comprises applying a plurality oflayers of the material composition onto the surface of the component,wherein at least two layers of the plurality of layers have differencesin the one or more polymeric materials, the one or more inorganicparticles, and/or the one or more metal particles.
 18. A system,comprising a surface monitoring system configured to measure dataindicative of a change in surface characteristics of a materialcomposition along the surface, wherein the material compositioncomprises: one or more polymeric materials, wherein the one or morepolymeric materials; one or more inorganic particles comprising oxides,carbonates, sulfides, or any combination thereof; one or more metalparticles configured to produce a detectable change in an electricalproperty or an optical property based on a reaction with at least one ofH₂O, CO₂, or H₂S; and wherein the one or more inorganic particles andthe one or more metal particles are dispersed within the one or morepolymeric materials; and wherein the surface monitoring system comprisesinstructions stored on a non-transitory computer-readable medium andexecutable by a processor to: identify the detectable change in theelectrical property or the optical property in response to the data; andoutput an indication of the detectable change.
 19. The system of claim18, comprising the material composition.
 20. The system of claim 19,comprising a component having a surface coated with the materialcomposition.